In a conventional fossil fuel-fired (e.g., coal-fired) steam generating unit a fossil fuel/air mixture is ignited in a boiler. Large volumes of water are pumped through tubes inside the boiler, and the intense heat from the burning fuel turns the water in the boiler tubes into high-pressure steam. In an electric power generating application, the high-pressure steam from the boiler passes into a turbine comprised of a plurality of turbine blades. Once the steam hits the turbine blades, it causes the turbine to spin rapidly. The spinning turbine causes a shaft to turn inside a generator, creating an electric potential. Alternatively, the high-pressure steam may be used for steam heating or other applications.
As used herein, the term “steam generating plant” refers to one or more steam generating units. A “power plant” refers herein to a steam generating plant used to drive turbines for generating electricity. A steam generating unit is typically powered by fossil fuels (including but not limited to, coal, natural gas or oil), and includes a boiler for producing high temperature steam; air pollution control (APC) devices for removal of pollutants from the flue gas; a stack for release of flue gas; and a water cooling system for condensing the high temperature steam. A typical steam generating unit will be described in detail below.
Boiler combustion or other characteristics of a fossil fuel-fired steam generating unit are influenced by dynamically varying plant parameters including, but not limited to, air to fuel ratios, operating conditions, boiler configuration, slag/soot deposits, load profile, fuel quality and ambient conditions. Changes to the business and regulatory environments have increased the importance of dynamic factors such as fuel variations, performance criteria, emissions control, operating flexibility and market driven objectives (e.g., fuel prices, cost of emissions credits, cost of electricity, etc.).
About half of the electric power generated in the United States is generated using coal-fired steam generating units. Coal typically contains trace amounts of mercury, and thus coal-fired steam generating units emit small amounts of mercury as a gaseous byproduct of coal combustion.
Mercury is a naturally occurring metallic element that exists in liquid form at room temperature. Mercury can combine with other elements, such as chlorine, sulfur or oxygen, to form inorganic compounds. Mercury can also combine with carbon to form organic mercury compounds. Methylmercury is one form of organic mercury in the environment, which can be toxic, easily absorbed in the digestive system of humans and wildlife, and not easy to eliminate once absorbed.
Forms of mercury are known to have toxic effects on the nervous system of humans and wildlife. Mercury released into the air from power plants can return to the land and water. In water, bacteria can transform certain species of the metal into methylmercury. Methylmercury can bio-accumulate in the aquatic food chain resulting in dangerously high concentrations of mercury in predatory fish and fish eating mammals and birds.
Due to concerns about the accumulation of mercury in fish, mammals and humans, on Mar. 15, 2005, the U.S. Environmental Protection Agency (EPA) issued a regulation for the control of mercury emissions from coal-fired power plants. The regulation requires coal-fired power plants in the United States to reduce emissions from an estimated 48 tons in 2003 to 38 tons in 2010. Emissions must be reduced to 15 tons by 2018.
Coal-fired steam generating units used in power plants typically have an assortment of air pollution control (APC) devices installed for reducing nitrogen oxides (NOx), sulfur oxides (SOx), and particulate emissions. In this regard, selective catalytic reduction (SCR) systems are used for NOx reductions. Spray dry absorbers (SDA) and wet flue gas desulfurization (FGD) systems are used for SOx reductions. Electo-static precipitators (ESPs) and fabric filters (FF) are used for reducing particulate emissions. Tests have shown that each of these devices or combinations of these devices are capable of removing or enhancing the removal of some portion of mercury from the flue gas.
Mercury appears in three forms in the flue gas from a coal-fired steam generating unit: elemental mercury, particulate bound mercury and oxidized mercury. The relative proportions of these three forms of mercury are referred to as the speciation.
The speciation of mercury depends upon the coal characteristics, fly ash properties, APC equipment configuration and other factors. Initially, as the coal is combusted at a high temperature in the furnace of the steam generating unit, the mercury is freed to a gaseous state. As the gas cools, a portion of the mercury oxidizes, into oxides such as into mercuric chloride, HgCl2, and a portion of oxidized or elemental mercury binds to the fly ash (particulate bound mercury).
In general, the speciation of the mercury is highly dependent upon the type of coal used for combustion. For example, a steam generating unit that burns bituminous coal typically average only 7% elemental mercury at the inlet of ESPs while those burning subbituminous average 70% elemental mercury at the inlet of ESPs.
The speciation of the mercury is an important factor in determining the amount of mercury that can be efficiently removed using currently installed APC equipment. Particulate bound mercury can be removed using ESPs and Fabric Filters. Since a common form of oxidized mercury, HgCl2, is water soluble, it can be efficiently removed by wet FGD systems. Mercury is also bound by fly ash and is also removed in the ESP and FF. SCRs can in many cases oxidize mercury such that it can be removed by other APC equipment. However, elemental mercury is not as readily captured by conventional APC equipment.
Continuous emission monitoring systems (CEMs) are available for on-line measurement of both total mercury emissions and elemental mercury emissions of a steam generating plant. In one common type of CEM, the mercury is measured by extracting hot filtered flue gas and transporting it using a heated line to a CEM module. The sampled gas is split into two streams for measurement of (a) elemental mercury and (b) total mercury. In the total mercury stream, the oxidized mercury is converted back to elemental mercury. In the elemental mercury stream, the oxidized mercury is removed. Using a common sensor, the resulting mercury can be used to measure the mercury in both streams, and thus determine the total and elemental levels of mercury in the flue gas.
Since particulate bound mercury and oxidized mercury are easier to remove than elemental mercury using standard APC equipment, the prior art has focused on various approaches for adsorbing mercury to carbon matter and/or oxidizing mercury.
One approach to oxidizing and/or adsorbing mercury to particulate matter is through the introduction of sorbents into the flue gas stream prior to an ESP or fabric filter. U.S. Pat. No. 3,662,523 to Revoir et al. (issued May 16, 1972) teaches a method for reducing mercury emissions by allowing the flue gas to flow through a fixed sorbent bed that is composed of activated carbon that has been chemically enhanced with halogen compounds. U.S. Pat. No. 4,889,698 to Moller et al. (issued Dec. 26, 1989) teaches the use of injecting activated carbon as a fine powder which is suspended in the flue gas stream and subsequently removed together with the particulate material formed by a spray dry absorption process. U.S. Pat. No. 5,672,323 to Bhat et al. (issued Sep. 30, 1997) teaches the injection of the combination of activated carbon and recycled fly ash prior to the ESP or wet FGD for removal of mercury. U.S. Pat. No. 6,818,043 to Chang et al. (issued Nov. 16, 2004) teaches a method of finely grinding a powdered adsorbent in a wet slurry and treating the resulting slurry with chemical additives to improve mercury removal capabilities of the sorbent. In general, the foregoing approaches require large amounts of sorbent which results in a significant increase in the cost of operating a steam generating unit. In addition, the injection of sorbents often leads to contamination of fly-ash. Because the fly-ash is often sold for other applications (e.g., the manufacture of cement and wall board), contamination can result in making the fly-ash unusable in these other applications. Consequently, the fly-ash may need to be disposed of in a landfill rather than sold.
Another method of improving mercury removal is through the injection of halogens (such as chlorine or bromine) into the flue gas stream. It has been observed that coal with high chlorine content tends to produce flue gas with a greater proportion of oxidized mercury than coal with low chlorine content. In general, bituminous coal has higher chlorine content than subbituminous coal, partially explaining the tendency for higher levels of oxidized mercury in flue gas from steam generating plants using bituminous coal. U.S. Pat. No. 4,729,882 to Ide et al. (issued Mar. 8, 1988) teaches a method of adding chlorine material into the combustion process to facilitate the oxidation of mercury. Similarly, U.S. Pat. No. 5,435,980 to Felsvang et al. (issued Jul. 25, 1995) teaches that mercury oxidation can be increased by introducing in chlorine based salts into the dry absorption zone of an SDA. U.S. Pat. No. 6,878,358 to Vosteen et al. (issued Apr. 12, 2005) teaches that injected bromine compounds oxidize mercury more effectively than chlorine compounds under the given conditions of high temperature and high sulfur content commonly observed in coal-fired steam generating units. A disadvantage of injecting chlorine and bromine (halogen) compounds into the flue gas stream is the potentially corrosive effects on the furnace, boiler, duct work, APC equipment and/or on the stack equipment. In addition, typically large amounts of halogen compounds must be injected at a potentially significant additional operational cost.
Still another approach to reducing mercury emissions is through modification of the combustion process. U.S. Pat. No. 6,863,005 to Lanier et al. (issued Mar. 8, 2005) teaches that combustion modifications such as overfire air (OFA), low NOx burners (LNB), reburning, and advanced reburning affect the amount of carbon in fly ash content. This patent describes a method for combining a variety of combustion modifications with an ash burnout system to increase carbon in ash and subsequently reduce elemental mercury. Similarly, U.S. Pat. No. 6,895,875 to Lissianski et al. (issued May 24, 2005) teaches several combustion configurations. Once again, the method includes collecting the fly ash with adsorbed mercury in a combustion waste treatment system. The disadvantage of the approaches described in these patents is that costly combustion modifications must be implemented. In addition, the resulting fly ash may not be saleable due to the high content of carbon.
Since the carbon content of the fly ash significantly affects the adsorption and oxidation of mercury as well as the usefulness of the fly ash in other applications such as the manufacturing of cement and wall board, on-line measurement of the carbon content, also known as carbon in ash (CIA), is beneficial. U.S. Pat. No. 5,729,470 to Baier et al. (issued Mar. 17, 1998) teaches a method for using a microwave based system for measuring the carbon content of fly ash in situ and in real-time from the flue gas of a coal-fired steam generating unit. Although the approach is useful for determining carbon content, the instrument is expensive and therefore not commonly used in the utility industry.
The present invention provides a system that overcomes the abovementioned drawbacks of the prior art, and provides advantages over the prior art approaches to controlling and estimating mercury emissions.